Wax deposition at the inside wall of oil pipelines is a severe problem in today's oil production infrastructure. When warm oil flows through a pipeline with cold walls, wax will precipitate and adhere to the walls. This in turn will reduce the pipeline cross-sectional area, which without proper counter measures will lead to a loss of pressure and ultimately to a complete blockage of the pipeline.
Existing technologies that deal with the problem by removing the deposits include:                Pigging: Mechanical scraping off the wax from the pipe wall at regular intervals.        Chemical inhibition: Addition of chemicals which prevent wax deposition.        Direct Electrical Heating (DEH): Electric heating keeps the pipeline warm (above the wax appearance temperature).        
Pigging is a complex and expensive operation. If no loop is available, a pig has to be inserted sub-sea using remote-operated vehicles. If more wax is deposited than the pig diameter is designed for the pig might get stuck in the pipeline, resulting in costly operations and stop in production to remove the pig.
Chemical inhibition is also expensive and there are currently no chemicals available that completely reduce wax deposition. The results of such inhibition are uncertain and the intervals and amounts of chemicals used are therefore often unnecessarily high. Further, the chemicals that are used are classified as environmentally very problematic and the dosage of such chemicals should be kept to a minimum.
Electric heating above the wax appearance temperature is very expensive due to both high installation and operational costs. Accordingly, electric heating is not feasible for long-distance transport.
The rate of depositing on the inside surface of a pipeline conducting a multiphase stream of hydrocarbons vary according to several parameters, such as the surrounding temperature (subterranean, air, sea water), the stream temperature, the pressure inside the pipeline, the composition of the stream and the distribution of phases in the stream. Without the possibility to measure the thickness of the deposits in the pipeline or equipment, the remedies above are applied relative often to be on the safe side, in order to avoid problematic build-up of deposits. This results in increased costs and risks in production as well as a negative impact on the environment.
The intervals of the remedies applied are only based on experience data of build-ups in test streams that do not necessarily behave similarly to the actual streams. In addition to the fact that different streams at different production sites behave differently, due to differences in the fluid parameters mentioned above, (temperature, pressure, composition, phase distribution), these parameters will also change in time within one single stream. This may be due to changes of the properties of the produced crude oil and gas which vary in a reservoir depending on degree of exploitation and from reservoir to reservoir. In addition, the profile or shape of the pipeline or any process equipment may have an impact on the rate of deposit build-up, which is not possible to simulate correctly in a laboratory.
In order to know when remediation techniques (e.g. pigging, heating, etc.) have to be applied, it therefore essential to know the current thickness of the wax layer.
Known techniques for determining or measure the current wax layer's thickness include the use of pipeline inspection gauges (pigs), pressure pulse techniques, and pressure drop measurement (over the complete pipeline).
However, each of these known techniques has several drawbacks. For instance, pigs and pressure pulse techniques give no continuous measurement, and they may disturb operation procedures, as well as being expensive. Further, pressure drop measurement only gives an integral measurement over the whole pipe length, not on specific troublesome areas, and the measured pressure drop is influenced by a number of parameters other than wax thickness (e.g. the roughness of the inside of the pipeline), so there is really no direct correlation to wax thickness.
U.S. Pat. No. 6,886,393 describes a method for detecting deposits on the inside of a fluid transporting pipe by the use of a heat source and a sensor, both mounted on a pipe and spaced apart. The heat source provides a thermal gradient and the sensor measures the resulting heat flux which is influenced by the presence of deposits in the pipe as heat is diffused into the fluid when no deposit is present, or transmitted by the pipe when a deposit is present acting as thermal insulation. A threshold for the measured heat flux is used for indicating the presence of deposits. U.S. Pat. No. 6,886,393 also indicates that the thickness of the deposit may be determined by comparing the measured heat flux with a heat flux measured during a calibration stage, however, no details of such calibration is given.
However, the heat flux will be affected by the fluid parameters mentioned above, (temperature, pressure, composition, phase distribution), which constantly change. The method described in U.S. Pat. No. 6,886,393 has no means of calibrating accordingly, taking these parameters into account when a deposit layer is present, and will therefore not provide the necessary accuracy in thickness calculation.
Hence, there is a need for a method for determining the thickness of process side wall deposits in pipelines or production equipment conducting multiphase flow which may perform calibration measurements simultaneously with real-time measurement of deposit thickness.